Enno Peters
This is an older blog post, you will find one on more recent data here
This interactive presentation contains the latest oil & gas production data from 10461 selected horizontal wells in the Permian (Texas & New Mexico) through October.
Despite an apparent drop in oil production in September and October 2016, I think that after revisions come in, we will see an increase in oil production during these months.
In the “Well quality” overview, we can see the average production rate of all these horizontal wells over time, grouped by the year in which they started production. You’ll notice that well productivity has increased every year, since 2013, and 2016 was no exception.
In the “Well status” overview the top graph shows that despite these improvements, the number of completions has slowly (relative to other oil basins) come down, since the end of 2014. Texas data for September and October appears to be incomplete; if you select the basin “Permian (NM)”, you’ll see that the number of completions was steady in New Mexico, during 2016.
Oil production of the top 5 operators can be seen in the last tab (“Top operators”). The rise in oil production of Pioneer Natural Resources over the last couple of years has been impressive. Also here, I suspect that the drop in the last 2 months is due to incomplete RRC data, on which we should get more clarity in the coming months.
The new ‘Advanced Insights’ presentation is displayed below:
This “Ultimate recovery” overview shows how all these horizontal wells progress towards their ultimate recovery, as their production rate slows down over time. Also this view shows clear improvements in well productivity in the last view years. If you show production here by “Quarter of first flow”, you’ll notice that this trend has continued in 2016.
Gas production is even faster on the rise, which will be visible if you change the “Product” selection to “Gas”.
The second overview (“Cumulative production ranking”) shows that Concho Resources has produced by far the most oil in this basin, using horizontal wells. By clicking on this operator, you’ll see exactly where its wells are located.
Coming Thursday I will have another update on the 8 states I cover in the US. Next week, I’ve planned an update on North Dakota, followed by a new “Projections” post.
Production data is subject to revisions, especially for the last few months in Texas. Note that a significant part of oil production in the Permian comes from vertical wells, which are excluded here.
For this presentation, I used data gathered from the following sources:
- Texas RRC. I’ve estimated individual well production from well status & lease production data, as these are otherwise not provided. Because of these estimations, I recommend looking at larger samples (>50 wells) before drawing conclusions. About 7% of the horizontal Permian wells in Texas are excluded, as these were mixed with too many vertical wells on a lease, making reasonable well profile estimations impossible. I’ve no spud, DUC, or plugging information on wells in Texas, so these statuses are unavailable. Detailed location data is available for all New Mexico wells, and for almost 95% of the Texan wells displayed; the remaining wells are shown near the center of the county in which they are located. Formation data in Texas is only available on lease level; therefore in cases where wells on the same lease are drilled in different formations, this information is not accurate.
- OCD in New Mexico. Accurate individual well production data is provided.
- FracFocus.org
====BRIEF MANUAL====
The above presentation has many interactive features:
- You can click through the blocks on the top to see the slides.
- Each slide has filters that can be set, e.g. to select individual or groups of operators. You can first click “all” to deselect all items. You have to click the “apply” button at the bottom to enforce the changes. After that, click anywhere on the presentation.
- Tooltips are shown by just hovering the mouse over parts of the presentation.
- You can move the map around, and zoom in/out.
- By clicking on the legend you can highlight selected items.
- Note that filters have to be set for each tab separately.
- The operator who currently owns the well is designated by “operator (current)”. The operator who operated a well in a past month is designated by “operator (actual)”. This distinction is useful when the ownership of a well changed over time.
- If you have any questions on how to use the interactivity, or how to analyze specific questions, please don’t hesitate to ask.
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37 Comments
Another one breaches the 2010 Curve (2013). Not surprisingly, 300 kBO EURs still a bridge too far [Enno: offensive part removed. Mark, please..].
Baseball Players everywhere must truly be jealous. They must actually deliver on their “one-third” promises whereas Public E&P merely posts another Conference Call or PwrPt Type Well they ultimately only deliver a third or less actual Cumulative Production upon and yet the Retail Equity Fools cheer in blissful ignorance all too happy to buy more dilutive stawks with which the Public E&Ps drill them into oblivian with.
The epitomy of Charles Ponzi.
It’s amazing there are 3,600 wells on that chart in 11, 12, and 13. They are going to be lucky to average 90 MSTBO gross cum. How much is the loss per well, $5 MM? That is an 18 billion dollar hole right there.
So, if you could manage to eek out an $18 margin somehow someway from your subsequent activity, that’s a billion barrels of oil or 3 years of the current production from this “play”.
“Give that man another shovel(rig)”
makes you wonder how lateral adj results would look like
Mark,
Please define “UFSA” for me.
Thanks
John,
Thanks for catching that, I’ve removed it.
@All
I expect that everybody can behave in this forum. I basically ask everybody just to adhere to 2 rules when commenting:
1. Respectful
2. On-topic
Otherwise, please take it to somewhere else.
I don’t like moderation, but these rules are more important. I will not give many warnings before deleting comments, or banning offensive users.
Uhhh… Enno,
I really don’t know what it means. Guess I’ve spent too much time in the wilderness. No worries all.
Thanks John,
I also don’t know what to make of it, but it looked bad to me after you mentioned it, so I removed it.
The performance of Reeves County is truly interesting.
Even though these appear to be the best 2016 wells hands down; the county production seems stuck at 115 MBOPD or so. Wonder if it is late in reporting, but the situation seems to have been going on a while.
If this is the county with the highest rig count and best wells, and the Permian production is growing, then??
I think Enno already pointed out that the last 2 months reports are not complete
Pioneer just announced their Q4 2016 production is 130MBOPD, but here it shows only above 100MBOPD.
Reeves county probably is experiencing similar things.
Thanks Sheng- do you know if that 130 MBOPD figure is net or gross, horizontal wells only or does it include verticals?
nice catch, Jim,
I think it is lateral and vertical combined reported in Pioneer’s Q4 ppt.
but their Q3 production is 120 MBOPD which matches 120MBOPD here.
They had ~40MBOePD before from vertical as projected to Q4 2016, which probably around 20MBOPD from vertical in Q4.
Can anybody comment on NG handling capabilities at Permian? This is important to know and it may limit the production at Permian at some point.
Enno:
Did I recall correctly that you had expected the Permian’s oil production to increase this month? Permian production looks flat over the last few months, despite a large rig count increase during that time frame. Is the first year decline rate of 72% the explanation for flat production or is there a lag from rig acquisition to production increase?
Thanks!
Joel,
I will mostly refrain from making forecasts, especially for a particular month. All the basins show sometimes unpredictable monthly fluctuations.
Production in Texas for the last few months is normally reported incompletely, by a few percent. Therefore, I think it’s better to ignore any downward changes in production during this period.
Given the rise in well productivities, and increasing rig count, I consider it very likely that in the coming half year we will see a trend of increasing production in the Permian. By how much, I don’t dare to say.
Please confirm, this is production summed from horizontal wells only? You are able to exclude production from new vertical wells completed in the basin during these periods? Thanks, Cy
CyEsp,
That is correct, in all my presentations I only show the performance of horizontal wells.
For Texas, I first estimate the production for all wells on a lease (both horizontal and vertical), using total lease production, and then finally report here only the production from the horizontal wells.
The thing about a reserve audit is the engineer doesn’t care what you spent or how you raised the money to get the production on the curve. All he cares about is the production forecast and lifting cost. That’s proved developed producing.
But proved undeveloped reserves require the auditor to determine if the capital outlay results in an economic investment, which reserves must meet to be called reserves.
They allow you to book offsets– up to 5 years worth.
PXD will finish with Netherland Sewell’s auditor identified locations end of this month.
Just sayin.
Thank you for your insights, Mr. Brooker.
Several things, please: It is interesting that 29% of its reserves are gas. That BOE thing really comes in handy in that case. was not aware one can book reserves based on SEC price schedules. I don’t know of anybody that received 2.59/MMBTU in 2015 at the well head, wow! I am raising hell about that first thing tomorrow morning. On its website Pioneer lays claim to 785,000 leased acres in the Permian Basin; is it suggesting that only of 7% of its assets are classified as PUD? Can you explain that to me, sir?
I might also ask you to explain what footnote 3) (iii) means regarding “technical revisions” of previously estimated proven developed reserves but for some reason I am not sure you could.
Mike
Mr Shellman
The PUD: I believe that you are only allowed to book (1) well locations that are adjacent to existing Proven Developed locations; 2) economic including the cost to drill.
Obviously, once you’ve drilled an uneconomic location that isn’t in reserves, it will become ‘Proved Developed’ at the end of the next year even if it’s not ‘Proved Undeveloped’.
Note that the management compensation for Pioneer’s CEO has some perverse effects: production and reserves growth are key in pay metrics, but there are ‘upper bounds’ – so there’s not much point booking extra reserves beyond a certain level if you don’t have to. Page 36 here has more details.
http://www.cstproxy.com/pioneer/2016/proxy/images/Pioneer_Natural_Resources-Proxy2016.pdf
[2] The footnote: there’s no direct explanation in there but I know from looking at the previous year’s release that their ‘technical revisions’ related to lower costs. So they put out a press release saying ‘excluding price related revisions, our reserve replacement was x’, but in reality these ‘technical revisions’ are from lower costs as a result of industry conditions which are a result of lower oil prices!
The “10-k” will have more detail. I’ve dug through a few – in a previous year (I think 2014), Pioneer revised down reserves on well performance being disappointing… a few others have done this – the only one I’ve seen revise upwards regularly is EOG Resources.
Thank you, Mr. Wheel; I understand reserve classifications and the SEC proximity rule for PUD’s. My question remains, why of all of PXD’s reserve estimates is only 7% PUD? In its 4Q16 it is touting tremendous growth in the future, I don’t understand where that is going to come from. Something is amiss.
As to your explanation for technical adjustments to existing, estimated reserves; lower costs is a possible answer, yes sir, though personally I think the rule of thumb should be to never believe a word the shale oil industry says about itself, even to the SEC, then divide by half. “Technical adjustments” is not a term I see very often, so I am suspicious of it.
Mr. Shellman,
In response to your previous question, the Pioneer 10-k for 2016 (released at the end of last week) states that the ‘technical revisions’ are indeed due to lower costs, which will increase economic recovery for existing producing wells in the long-term.
Greasy.
Thank you. Lower OPEX, got it. Scott said six months ago it was as low as 2.00 per incremental BOE. In my production meeting this morning I am going to try that; I am going to declare that technical revisions over the weekend caused my OPEX to decline; produced water costs no longer exist, all downhole maintenance costs are now classified CAPEX, not OPEX, and henceforth, we have no more corporate overhead. All that has led to a magical increase in PDP reserves and things are peachy. It won’t be true, but I am going to say it anyway. It’ll be a good way to start the week.
Thanks again.
It seems one of the major unanswered questions is how Permian Wells will behave long term.
On Enno’s log rate versus cumulative, harmonic decline with a b exponent 1 is a straight line. If a curve is more concave down, it is becoming exponential in nature.
Apache corporation published some simulated Wolfcamp results projecting oil recovery for a 23 stage 9,000′ horizontal well with 4 perf spacings in 2014. They varied the initial solution gas oil ratio and ran 3 cases, which is the snapshot graph in the lower right below.
In the left hand curve, these Apache results are the colored dots. This is a log rate versus cumulative oil plot identical to the advanced insights curve Enno provides above. Overlain on this family of simulator or theoretical curves are Pioneer Natural Resources 2013 wells, and the last 4 quarters with data available.
I was also generously provided with a 700 MSTBO oil curve that represented the “2016 Normalized Curve” from a Permian Basin Operator- this is the black dotted line. This would come close to approximating a 1 MMBOE curve we are accustomed to seeing 180 or 240 day comparisons to. But here we have been given the entire life of the well.
The Apache curves land somewhere between an oil EUR of 230-and 280 MSTB at 10 BOPD.
You decide which of the theoretical examples the actual data appears to be following.
Jim
Does anyone see how the parlor trick of showing 180 and 360 day “tracking above” the 1 MMBOE type curve is played?
Hi Jim, I believe on a semi-log rate cum plot, concave down means the hyperbolic “b” factor is less than 1, concave up is greater than one, and straight is a harmonic decline. We generally match tight Permian production history with a “b” factor greater than one, and I believe this is typical in the industry. The new, larger fracs may have a different decline, but we need more time to observe if it has a different character.
Cy-
Thanks. There is little in the Public Domain (SPE etc) that I can find on how theoretical permian wells should behave- that is why I included the Apache simulator runs- which have characteristics of a b value less than 1.
Jim
@ Jim Brooker.
Firstly, appreciate your charts and insights – adds to the great work Enno does.
Secondly, wanted to follow-up on this. As much as I can tell, the permeability of the ‘matrix’ in the Wolfcamp sits between the Eagle Ford (lower) and Bakken (which is higher). I can’t immediately see why the longer-term decline rate in the Wolfcamp would not sit somewhere between the two areas, and therefore the ‘b’ factor should sit somewhere between the two as well.
Or why can we not use the guide of the existing (e.g. 2013-2014) horizontal wells’ later life production as some guide? Many things have changed in the development of shale, but the one thing that hasn’t is that long-term production performance will still be determined by the typical ‘matrix’ rock.
Greasy Wheel- you are right, normally an engineer will look to the earlier horizontal wells to estimate the b factor for a new well. The declines from the new frac’s often look very different than the wells from 2 years ago. Much greater volumes and lower viscosity are contacting more reservoir with less conductivity in the induced fracture. Both constructive and deleterious interference with offsetting wells are more common with new tighter spacing and “wine rack” horizontal patterns. These factors, plus undoubtedly others, make relying on older completion decline behavior to predict new well production forecasts less certain.
Mr. ESP, I sense you are attempting to make a case for 1MBOE EUR’s in the Permian. If that is the happy medium between Bakken and Eagle Ford, sorry, I am not buying into that.
That aside, I am more interested in what you mean by the “constructive” aspects of well interference based on tighter spacing. What is constructive, economically, about well interference due to tighter spacing? Thanks for your answer.
Mike, by constructive interference I was referring to fracing multiple wells in close proximity at approximately the same time. When multiple nearby wells are stimulated together before flowing back the frac fluid the stimulated rock volume is maximized. The elevated, induced formation pressure from the fracs in one well will encourage the fracs in the adjoining well to grow into lesser pressured, unstimulated portions of the reservoir. While rubblization is an overstatement, that is the intended effect. This improves recovery for very tite rocks with multiple stringers of pay encased in shale such as the Wolfcamp, Bone Springs, or even the Niobrara. The opposite occurs in when stimulating a well in an area of lowered pressure (production), the frac in the new well will preferentially grow into the depleted lower presser portion of the reservoir. The risk of leaving significant portions of the reservoir unstimulated and thereby undrained is substantial.
Optimal spacing is a multi variant problem. Here is a hypothetical example. If you have a 1/4 mile by 1 mile spacing unit (160 acre spacing) your first well might recover 6% of the ooip in 30 years. If you instead drilled 2 wells (now 80 acre spacing) at the same time the two wells might recover 10% of the ooip in 25 years, if you drill 4 wells (very close 40 acre spacing) you might recover 14% of the ooip in 20 years. Obviously there is interference, but there is also some additional recovery and acceleration of recovery. But these incremental recoveries can only be obtained by drilling the wells at the same time, its a one time opportunity. So, the spacing an operator uses is driven by their well costs and business goals.
Thank you for the answer, Mr. ESP. Zipper frac’ing has been used extensively in the Eagle Ford for years and I understand the mechanics of it quite well. I asked because in the EF constructive interference seems to be turning into a lot of deconstructive well communication.
I suspect if you were to challenge Marathon on its optimal spacing in the EF (toe to toe @330 ft.) it might say it overcooked it. It should say that, based on Enno’s actual production data, but of course it wouldn’t say that. In its case I might argue those well densities are not economic, have only marginally increased the rate of extraction per incremental well and we will never know if RF of OOIP was improved as a lot of those wells are headed for economic limits and pre-mature death.
Thanks again.
Mike
CyEsp, Mike,
Thank for your adding to this discussion. I much appreciate the input from experts on this unfolding story.
On the issue of spacing: there’s a good SPE paper by Shell covering the optimal spacing in the Wolfcamp.
They set out different examples of EUR/well depending upon the number of wells:
e.g. up to 4 wells / section, there’s very little effect upon EUR/well.
At 5 wells, interference starts to take place, and EUR/well drops slightly, but only about 3-5% or so
At 6 wells/section – the impact on EUR/well is almost 20%.
At 8 wells/section, the impact is around 40%.
(Essentially, beyond 5 wells per section, there really is very little additional oil that is recovered in the long-term).
Where does Occidental fit on the rankings of top operators? They claim to produce something like a quarter million bpd in the Permian, and I have long heard they are the top operator there.
Robert,
I can’t speak to any specifics regarding Oxy, but I believe it’s primary focus in the Permian is Enhanced Oil Recovery specifically CO2 tertiary floods.
EOR is typically a high cost, low ROR business but it is a hugh cash flow (except in a low price, over supplied environment) once the field begins to respond. Also, the skill set is highly specialized so the labor pool is pretty small.
Steve Melzer is a CO2 consultant and he has some interesting stuff on his website that is linked below.
Robert,
If you look at the 2nd presentation (“Advanced Insights”), and then click on the 2nd tab (“Cumulative production ranking”), you will see the list of operators, based on their cumulative production. If you scroll down a bit, you will see Occidental.
Note that I only report production from horizontal wells. It could be that some of these operators have far greater production from vertical wells, which I don’t show here.
EIA is currently reporting nearly 9 million b/d in US oil production, but Energy Aspects says 8.6 million b/d in October and Core Labs says about 8.3 million barrels. If there was growth in US oil production from October -December 2016, it was probably de minimus because the Eagleford would have offset much of the Permian growth.
Is the EIA lying?